The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
The present disclosure relates generally to wellbore treatment and development of a reservoir and, in particular, to a method for determining flow distribution in a wellbore during a treatment.
Hydraulic fracturing, matrix acidizing, and other types of stimulation treatments are routinely conducted in oil and gas wells to enhance hydrocarbon production. The wells being stimulated often include a large section of perforated casing or an open borehole having significant variation in rock petrophysical and mechanical properties. As a result, a treatment fluid pumped into the well may not flow to all desired hydrocarbon bearing layers that need stimulation. To achieve effective stimulation, the treatments often involve the use of diverting agents in the treating fluid, such as chemical or particulate material, to help reduce the flow into the more permeable layers that no longer need stimulation and increase the flow into the lower permeability layers.
One method includes conducting the treatment through a coiled tubing, which can be positioned in the wellbore to direct the fluid immediately adjacent to layers that need to be plugged when pumping a diverter and adjacent to layers that need stimulation when pumping stimulation fluid. However, the coiled tubing technique requires an operator to know which layers need to be treated by a diverter and which layers need to be treated by a stimulation fluid. In a well with long perforated or open intervals with highly non-uniform and unknown rock properties, typical of horizontal wells, effective treatment requires knowledge of the flow distribution in the treated interval.
Traditional flow measurement in a well is typically done through production logging using a flow meter to measure the hydrocarbon production rate or injection rate in the wellbore as a function of depth. Based on the logged wellbore flow rate, the production from or injection rate into each formation depth interval is determined based on a measured axial flow rate over that interval. Traditional flow measurement is valid as long as the flow distribution in the well does not change over the time period when logging is conducted.
However, during a stimulation treatment, the flow distribution in a well can change quickly due to either stimulation of the formation layers to increase their flow capacity or temporary reduction in flow capacity as a result of diverting agents. To determine the effectiveness of stimulation or diversion in the well, an instantaneous measurement that gives a “snap shot” of the flow distribution in a well is desired. Unfortunately, there are few such techniques available.
One technique for substantially instantaneous measurement is fiber optic Distributed Temperature Sensing (DTS) technology. DTS typical includes an optical fiber disposed in the wellbore (e.g. via a permanent fiber optic line cemented in the casing, a fiber optic line deployed using a coiled tubing, or a slickline unit). The optical fiber measures a temperature distribution along a length thereof based on an optical time-domain (e.g. optical time-domain reflectometry (OTDR), which is used extensively in the telecommunication industry).
One advantage of DTS technology is the ability to acquire in a short time interval the temperature distribution along the well without having to move the sensor as in traditional well logging which can be time consuming. DTS technology effectively provides a “snap shot” of the temperature profile in the well. DTS technology has been utilized to measure temperature changes in a wellbore after a stimulation injection, from which a flow distribution of an injected fluid can be qualitatively estimated. The inference of flow distribution is typically based on magnitude of temperature “warm-back” during a shut-in period after injecting a fluid into the wellbore and surrounding portions of the formation. The injected fluid is typically colder than the formation temperature and a formation layer that receives a greater fluid flow rate during the injection has a longer “warm back” time compared to a layer or zone of the formation that receives relatively less flow of the fluid.
As a non-limiting example, FIG. 1 illustrates a graphical plot 2 of a plurality of simulated temperature profiles 4 of a laminated formation 6 during a six hour time period of “warm back”, according to the prior art. As shown, the X-axis 8 of the graphical plot 2 represents temperature in Kelvin (K) and the Y-axis 9 of the graphical plot 2 represents a depth in meters (m) measured from a pre-determined surface level. As shown, a permeability of each layer of the laminated formation 6 is estimated in units of millidarcies (mD). The layers of the formation 6 having a relatively high permeability receive more fluid during injection and a time period for “warm back” is relatively long (i.e. after a given time period, a change in temperature is less than a change in temperature of the layers having a lower permeability). The layers of the formation 6 having a relatively low permeability receive less fluid during injection and a time period for “warm back” is relatively short (i.e. after a given time period, a change in temperature is greater than a change in temperature of the layers having a higher permeability).
By obtaining and analyzing multiple DTS temperature traces during the shut-in period, the injection rate distribution among different formation layers can be determined. However, current DTS interpretation techniques and methods are based on visualization of the temperature change in the DTS data log, and is qualitative in nature, at best. The current interpretation methods are further complicated in applications where a reactive fluid, such as acid, is pumped into the wellbore, wherein the reactive fluid reacts with the formation rock and can affect a temperature of the formation, leading to erroneous interpretation. In order to achieve effective stimulation, more accurate DTS interpretation methods are needed to help engineers determine the flow distribution in the well and make adjustments in the treatment accordingly.
This disclosure proposes several methods for quantitatively determining the flow distribution from DTS measurement. These methods are discussed in detail below.